Method of Treating Subterranean Formations With Porous Ceramic Particulate Materials

ABSTRACT

Methods and compositions useful for subterranean formation treatments, such as hydraulic fracturing treatments and sand control that include porous materials. Such porous materials may be selectively configured porous material particles manufactured and/or treated with selected glazing materials, coating materials and/or penetrating materials to have desired strength and/or apparent density to fit particular downhole conditions for well treating such as hydraulic fracturing treatments and sand control treatments. Porous materials may also be employed in selected combinations to optimize fracture or sand control performance, and/or may be employed as relatively lightweight materials in liquid carbon dioxide-based well treatment systems.

This application is a continuation application of U.S. patentapplication Ser. No. 10/653,521, filed on Sep. 2, 2003 which claimspriority to provisional application Ser. No. 60/407,734, filed on Sep.3, 2002 and provisional application Ser. No. 60/428,836, filed on Nov.25, 2002.

FIELD OF THE INVENTION

This invention relates generally to methods and compositions useful forsubterranean formation treatments, such as hydraulic fracturingtreatments and sand control.

BACKGROUND OF THE INVENTION

Hydraulic fracturing is a common stimulation technique used to enhanceproduction of fluids from subterranean formations. In a typicalhydraulic fracturing treatment, fracturing treatment fluid containing asolid proppant material is injected into the formation at a pressuresufficiently high enough to cause the formation or enlargement offractures in the reservoir. During a typical fracturing treatment,proppant material is deposited in a fracture, where it remains after thetreatment is completed. After deposition, the proppant material servesto hold the fracture open, thereby enhancing the ability of fluids tomigrate from the formation to the well bore through the fracture.Because fractured well productivity depends on the ability of a fractureto conduct fluids from a formation to a wellbore, fracture conductivityis an important parameter in determining the degree of success of ahydraulic fracturing treatment.

Hydraulic fracturing treatments commonly employ proppant materials thatare placed downhole with a gelled carrier fluid such as aqueous-basedfluid such as gelled brine. Gelling agents for proppant carrier fluidsmay provide a source of proppant pack and/or formation damage, andsettling of proppant may interfere with proper placement downhole.Formation damage may also be caused by gelled carrier fluids used toplace particulates downhole for purposes such as for sand control, suchas gravel packs, frac packs, and similar materials. Formulation ofgelled carrier fluids usually requires equipment and mixing stepsdesigned for this purpose.

Hydraulic fracturing treatments may also employ proppant materials thatare placed downhole with non-aqueous-based fluids, such as liquid CO₂and liquid CO₂/N₂ systems. Proppants commonly employed with suchnon-aqueous-based fluids tend to settle in the system.

Many different materials have been used as proppants including sand,glass beads, walnut hulls, and metal shot. Commonly used proppants todayinclude various sands, resin-coated sands, intermediate strengthceramics, and sintered bauxite; each employed for their ability to costeffectively withstand the respective reservoir closure stressenvironment. As the relative strength of the various materialsincreases, so too have the respective particle densities, ranging from2.65 g/cc for sands to 3.4 g/cc for the sintered bauxite. Unfortunately,increasing particle density leads directly to increasing degree ofdifficulty with proppant transport and a reduced propped fracture volumefor equal amounts of the respective proppant, reducing fractureconductivity. Previous efforts undertaken to employ lower densitymaterials as proppant have generally resulted in failure due toinsufficient strength to maintain fracture conductivity at even thelowest of closure stresses (1,000 psi).

Recently, deformable particles have been developed. Such deformableparticles for sand flowback control are significantly lighter thanconventional proppants, and exhibit high compressive strength Suchdeformable materials include polystyrene divinylbenzene (PSDVB)deformable beads. Such beads, however, have not been entirely successfulprimarily due to limitations of the base material. While PSDVB beadsoffered excellent deformability and elasticity, they lacked thestructural integrity to withstand high closure stresses andtemperatures.

The first successful path to generate functional deformable particleswas the usage of modified ground walnut hulls. Walnut hulls in theirnatural state have been used as proppants, fluid loss agents and lostcirculation materials for many years with greater or lesser degrees ofsuccess in each respective task. As a proppant, natural walnut hullshave very limited applicability, because they deform fairly readily uponapplication of closure stress. This deformation drastically reducesconductivity and limits utility of the natural material to relativelylow-closure environments.

Walnut hull based ultra-lightweight (UCW) proppants may be manufacturedin a two-step process by using closely sized walnut particles (i.e.20/30 US mesh), and impregnating them with strong epoxy or other resins.These impregnated walnut hull particles are then coated with phenolic orother resins in a fashion similar to most resin coated proppants (RCP).Such walnut hull based ULW proppants have a bulk density of 0.85grams/cc and withstand up to 6,000 psi (41.4 MPa) closure stress at 175°F. (79° C.).

Generally speaking, the stronger a proppant, the greater the density. Asdensity increases, so too does the difficulty of placing that particleevenly throughout the created fracture geometry. Excessive settling canoften lead to bridging of the proppant in the formation before thedesired stimulation is achieved. The lower particle density reduces thefluid velocity required to maintain proppant transport within thefracture, which, in turn, provides for a greater amount of the createdfracture area to be propped.

ULW proppants which allow for optimization of fracturing treatment withimproved fracture length and well productivity are therefore desired.

SUMMARY OF THE INVENTION

The invention relates to methods for treating subterranean formations bytreating a well with a composition containing porous ceramic or organicpolymeric particulates. In particular, the compositions introduced intothe well are particularly suitable in hydraulic fracturing of a well aswell as sand consolidation methods such as gravel packing and fracpacking. The porous particulate material may be a selectively configuredporous particulate material, as defined herein. Alternatively, theporous particulate material may be a non-selectively configured porousparticulate material, as defined herein.

The porous particulate material may be selectively configured with anon-porous penetrating material, coating layer or glazing layer. In apreferred embodiment, the porous particulate material is a selectivelyconfigured porous particulate material wherein either (a.) the apparentdensity or apparent specific gravity of the selectively configuredporous particulate material is less than the apparent density orapparent specific gravity of the porous particulate material; (b.) thepermeability of the selectively configured porous particulate materialis less than the permeability of the porous particulate material; or(c.) the porosity of the selectively configured porous particulatematerial is less than the porosity of the porous particulate material.

In a preferred embodiment, the penetrating material and/or coating layerand/or glazing layer of the selectively configured porous particulatematerial is capable of trapping or encapsulating a fluid having anapparent specific gravity less than the apparent specific gravity of thecarrier fluid. Further, the coating layer and/or penetrating materialand/or glazing material may be a liquid having an apparent specificgravity less than the apparent specific gravity of the matrix of theporous particulate material.

The strength of the selectively configured porous particulate materialis typically greater than the strength of the porous particulatematerial per se. Further, the selectively configured porous materialexhibits crush resistance under conditions as high as 10,000 psi closurestress, API RP 56 or API RP 60.

In a preferred mode, the porous particulate composition is a suspensionof porous particulates in a carrier fluid. The suspension preferablyforms a pack of particulate material that is permeable to fluidsproduced from the wellbore and substantially prevents or reducesproduction of formation materials from the formation into the wellbore.

Further, the porous particulate material may exhibit a porosity andpermeability such that a fluid may be drawn at least partially into theporous matrix by capillary action. Preferably, the porous particulatematerial has a porosity and permeability such that a penetratingmaterial may be drawn at least partially into the porous matrix of theporous particulate material using a vacuum and/or may be forced at leastpartially into the porous matrix under pressure.

The selectively configured porous particulate material may consist of amultitude of coated particulates bonded together. In such manner, theporous material is a cluster of particulates coated with a coating orpenetrating layer or glazing layer. Suitable coating layers orpenetrating materials include liquid and/or curable resins, plastics,cements, sealants, or binders such as a phenol, phenol formaldehyde,melamine formaldehyde, urethane, epoxy resin, nylon, polyethylene,polystyrene or a combination thereof. In a preferred mode, the coatinglayer or penetrating material is an ethyl carbamate-based resin.

In a preferred embodiment, the selectively configured porous particulatematerials are derived from lightweight and/or substantially neutrallybuoyant particles. The application of selected porous materialparticulates and relatively lightweight and/or substantially neutrallybuoyant particulate material as a fracture proppant particulateadvantageously provides for substantially improved overall systemperformance in hydraulic fracturing applications, or in other welltreating applications such as sand control.

The porous particulate material-containing compositions used in theinvention may further contain a carrier fluid. The carrier fluid may bea completion or workover brine, salt water, fresh water, a liquidhydrocarbon, or a gas such as nitrogen or carbon dioxide.

The porous particulate material-containing compositions may furthercontain a gelling agent, crosslinking agent, gel breaker, surfactant,foaming agent, demulsifier, buffer, clay stabilizer, acid or a mixturethereof.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to more fully understand the drawings referred to in thedetailed description of the present invention, a brief description ofeach drawing is presented, in which:

FIG. 1 is a graph depicting bulk apparent density comparison of the dataof Example 1.

FIG. 2 is a graph depicting permeability versus closure stress data ofExample 2.

FIG. 3 is a graph depicting conductivity versus closure stress data ofExample 2.

FIG. 4 is a graph depicting conductivity versus closure stress data ofExample 2.

FIG. 5 is a graph depicting permeability versus closure stress data ofExample 2.

FIG. 6 is a graph depicting conductivity comparison data of Example 2.

FIG. 7 is a graph depicting permeability comparison data of Example 2.

FIG. 8 is a SEM photograph of a porous material particle of Example 3.

FIG. 9 is a SEM photograph of a porous material particle of Example 3.

FIG. 10 is a SEM photograph of a porous material particle of Example 3.

FIG. 11 is a SEM photograph of a porous material particle of Example 3.

FIG. 12 is a SEM photograph of a porous material particle of Example 3.

FIG. 13 is a SEM photograph of a porous material particle of Example 3.

FIG. 14 is a SEM photograph of a porous material particle of Example 3.

FIG. 15 is a SEM photograph of a porous material particle of Example 3.

FIG. 16 illustrates proppant distribution for a selected combination ofwell treatment particulates according to one embodiment of the disclosedcompositions and methods described in Example 4.

FIG. 17 illustrates comparative proppant distribution data of Example 4for Ottawa sand alone.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

As used herein, the following terms shall have the designated meanings:

“porous particulate material” shall refer to porous ceramic or porousorganic polymeric materials. Examples of types of materials suitable foruse as porous material particulates include particulates having a porousmatrix;

“selectively configured porous particulate material” shall refer to anyporous particulate material, natural or non-natural, which has beenchemically treated, such as treatment with a coating material; treatmentwith a penetrating material; or modified by glazing. The term shallinclude, but not be limited to, those porous particulate materials whichhave been altered to achieve desired physical properties, such asparticle characteristics, desired strength and/or apparent density inorder to fit particular downhole conditions for well treating such ashydraulic fracturing treatments and sand control treatments.

“non-selectively configured porous particulate material” shall refer toany porous natural ceramic material, such as lightweight volcanic rocks,like pumice, as well as perlite and other porous “lavas” like porous(vesicular) Hawaiian Basalt, porous Virginia Diabase, and Utah Rhyolite.Further, inorganic ceramic materials, such as alumina, magnetic glass,titanium oxide, zirconium oxide, and silicon carbide may also be used.In addition, the term shall refer to a synthetic porous particulatematerial which has not been chemically treated and which imparts desiredphysical properties, such as particle characteristics, desired strengthand/or apparent density in order to fit particular downhole conditionsfor well treating;

“relatively lightweight” shall refer to a porous particulate materialthat has a apparent density (API RP 60) that is substantially less thana conventional particulate material employed in hydraulic fracturing orsand control operations, such as sand having an apparent specificgravity (API RP 60) of 2.65 and bauxite having an apparent specificgravity of 3.55. The apparent specific gravity of a relativelylightweight material is less than about 2.4.

“substantially neutrally buoyant” shall refer to a porous particulatematerial that has an apparent density sufficiently close to the apparentdensity of a selected ungelled or weakly gelled carrier fluid, such asan ungelled or weakly gelled completion brine, other aqueous-basedfluid, slick water, or other suitable fluid, which allows pumping andsatisfactory placement of the proppant/particulate using the selectedungelled or weakly gelled carrier fluid.

a “weakly gelled carrier fluid” is a carrier fluid having a viscosifieror friction reducer to achieve friction reduction when pumped down hole,for example when pumped down tubing, work string, casing, coiled tubing,drill pipe, or similar location, wherein the polymer or viscosifierconcentration from about 0 pounds of polymer per thousand gallons ofbase fluid to about 10 pounds of polymer per thousand gallons of basefluid, and/or the viscosity from about 1 to about 10 centipoises. An“ungelled carrier fluid” is a carrier fluid having no polymer orviscosifier. The ungelled carrier fluid may contain a friction reducerknown in the art.

The selectively configured porous particulate materials as well asnon-selectively configured porous particulate materials are particularlyeffective in hydraulic fracturing as well as sand control fluids such aswater, salt brine, slickwater such as slick water fracture treatments atrelatively low concentrations to achieve partial monolayer fractures,low concentration polymer gel fluids (linear or crosslinked), foams(with gas) fluid, liquid gas such as liquid carbon dioxide fracturetreatments for deeper proppant penetration, treatments for watersensitive zones, and treatments for gas storage wells.

For instance, the selectively configured porous material particles ornon-selectively configured porous material particles may be mixed andpumped during any desired portion/s of a well treatment such ashydraulic fracturing treatment or sand control treatment and may bemixed in any desired concentration with a carrier fluid. In this regard,any carrier fluid suitable for transporting the selectively configuredporous particulate material or non-selectively configured porousparticulate material particles into a well and/or subterranean formationfracture in communication therewith may be employed including, but notlimited to, carrier fluids comprising salt water, fresh water, potassiumchloride solution, a saturated sodium chloride solution, liquidhydrocarbons, and/or nitrogen or other gases may be employed. Suitablecarrier fluids include or may be used in combination with fluids havegelling agents, cross-linking agents, gel breakers, surfactants, foamingagents, demulsifiers, buffers, clay stabilizers, acids, or mixturesthereof.

When used in hydraulic fracturing, the selectively configured porousparticulate material or non-selectively configured porous particulatematerial particles may be injected into a subterranean formation inconjunction with a hydraulic fracturing treatment or other treatment atpressures sufficiently high enough to cause the formation or enlargementof fractures. Such other treatments may be near wellbore in nature(affecting near wellbore regions) and may be directed toward improvingwellbore productivity and/or controlling the production of fractureproppant or formation sand. Particular examples include gravel packingand “frac-packs.” Moreover, such particles may be employed alone as afracture proppant/sand control particulate, or in mixtures in amountsand with types of fracture proppant/sand control materials, such asconventional fracture or sand control particulate. Further informationon hydraulic fracturing methods and materials for use therein may befound in U.S. Pat. No. 6,059,034 and in U.S. Pat. No. 6,330,916, whichare incorporated herein by reference.

When employed in well treatments, selected porous material particlesthat have been selectively configured, such as glazed and/or treatedwith one or more selected coating and/or penetrating materials, may beintroduced into a wellbore at any concentration/s deemed suitable oreffective for the downhole conditions to be encountered. For example, awell treatment fluid may include a suspension of proppant or sandcontrol particulate that is made up completely of relatively lightweightselected porous material particles that have been selectivelyconfigured, such as glazed and/or treated with one or more selectedcoating and/or penetrating materials. Alternatively, it is possible thata well treatment fluid may include a suspension that contains a mixtureof conventional fracture proppant or sand control particulates such assand with relatively lightweight selected porous material particles thathave been selectively configured such as glazed and/or treated with oneor more selected coating and/or penetrating materials.

In one exemplary embodiment, a gravel pack operation may be carried outon a wellbore that penetrates a subterranean formation to prevent orsubstantially reduce the production of formation particles into thewellbore from the formation during production of formation fluids. Thesubterranean formation may be completed so as to be in communicationwith the interior of the wellbore by any suitable method known in theart, for example by perforations in a cased wellbore, and/or by an openhole section. A screen assembly such as is known in the art may beplaced or otherwise disposed within the wellbore so that at least aportion of the screen assembly is disposed adjacent the subterraneanformation. A slurry including the selectively configured porousparticulate material or non-selectively configured porous particulatematerial and a carrier fluid may then be introduced into the wellboreand placed adjacent the subterranean formation by circulation or othersuitable method so as to form a fluid-permeable pack in an annular areabetween the exterior of the screen and the interior of the wellbore thatis capable of reducing or substantially preventing the passage offormation particles from the subterranean formation into the wellboreduring production of fluids from the formation, while at the same timeallowing passage of formation fluids from the subterranean formationthrough the screen into the wellbore. It is possible that the slurry maycontain all or only a portion of selectively configured porousparticulate material or the non-selectively configured porousparticulate material. In the latter case, the balance of the particulatematerial of the slurry may be another material, such as a conventionalgravel pack particulate.

As an alternative to use of a screen, the sand control method may usethe selectively configured porous particulate material ornon-selectively configured porous particulate material in accordancewith any method in which a pack of particulate material is formed withina wellbore that it is permeable to fluids produced from a wellbore, suchas oil, gas, or water, but that substantially prevents or reducesproduction of formation materials, such as formation sand, from theformation into the wellbore. Such methods may or may not employ a gravelpack screen, may be introduced into a wellbore at pressures below, at orabove the fracturing pressure of the formation, such as frac pack,and/or may be employed in conjunction with resins such as sandconsolidation resins if so desired.

The porous particulate material shall include any naturally occurring ormanufactured or engineered porous ceramic particulate material that hasan inherent and/or induced porosity. A commercially availableinstrument, ACCUPYC 1330 Automatic Gas Pycnometer (Micromeritics,Norcross, Ga.), that uses Helium as an inert gas and the manufacturer'srecommended procedure can be used to determine the internal porosity ofthe particulates. The internal porosity is generally from about 10 to 75volume percent. Such particulate material may also have an inherent orinduced permeability, i.e., individual pore spaces within the particleare interconnected so that fluids are capable of at least partiallymoving through the porous matrix, such as penetrating the porous matrixof the particle, or may have inherent or induced non-permeability,individual pore spaces within the particle are disconnected so thatfluids are substantially not capable of moving through the porousmatrix, such as not being capable of penetrating the porous matrix ofthe particle. The degree of desired porosity interconnection may beselected and engineered into the non-selectively configured porousparticulate material. Furthermore such porous particles may be selectedto have a size and shape in accordance with typical fracturing proppantparticle specifications (i.e., having a uniform shape and sizedistribution), although such uniformity of shape and size is notnecessary.

The apparent specific gravity of the porous particulate material isgenerally less than or equal to 2.4, preferably less than or equal to2.0, even more preferably less than or equal to 1.75, most preferablyless than or equal to 1.25.

In a selectively configured porous particulate material, the particlesmay be selected based on porosity and/or permeability characteristics sothat they have desired lightweight characteristics, such as whensuspended in a selected carrier fluid for a well treatment. As before,the inherent and/or induced porosity of a porous material particle maybe selected so as to help provide the desired balance between apparentdensity and strength. Optional materials may be employed along with aglazing, penetrating and/or coating material to control penetration,such as enhancing or impairing penetration. For example, in oneembodiment an cationic clay stabilizer, such as CLAY MASTER 5C from BJServices, may be first applied to the exterior surface of a porousceramic material to inhibit penetration by coating/penetrating material,such as epoxy or resin described elsewhere herein.

In a preferred embodiment, the porous particulate material is arelatively lightweight or substantially neutral buoyant particulatematerial. Such materials may be employed in a manner that eliminates theneed for gellation of carrier fluid, thus eliminating a source ofpotential proppant pack and/or formation damage. Furthermore, arelatively lightweight particulate material may be easier to placewithin a targeted zone due to lessened settling constraints, and areduced mass of such relatively lightweight particulate material isgenerally required to fill an equivalent volume than is required withconventional sand control particulates, used, for example, for gravelpacking purposes.

Relatively lightweight and/or substantially neutrally buoyant fractureproppant/particulate material used in hydraulic fracturing/sand controltreatment, such as porous ceramic particles having untreated bulkapparent density of 1.16 and untreated porosity of about 59.3%, may beemployed.

In one embodiment, the disclosed porous material particulates may beemployed as relatively lightweight particulate/proppant material thatmay be introduced or pumped into a well as neutrally buoyant particlesin, for example, a saturated sodium chloride solution carrier fluid or acarrier fluid that is any other completion or workover brine known inthe art, thus eliminating the need for damaging polymer or fluid lossmaterial. In one embodiment, such a material may be employed asproppant/sand control particulate material at temperatures up to about700° F., and closure stresses up to about 8000 psi. However, theseranges of temperature and closure stress are exemplary only, it beingunderstood that the disclosed materials may be employed as proppant/sandcontrol materials at temperatures greater than about 700° F. and/or atclosure stresses greater than about 8000 psi. In any event, it will beunderstood with benefit of this disclosure that porous particulatematerial and/or coating/penetrating materials may be selected by thoseof skill in the art to meet and withstand anticipated downholeconditions of a given application.

In those embodiments where the disclosed porous material particulatesare employed as relatively lightweight and/or substantially neutrallybuoyant particulate/proppant materials, they may be employed withcarrier fluids that are gelled, non-gelled, or that have a reduced orlighter gelling requirement as compared to carrier fluids employed withconventional fracture treatment/sand control methods. In one embodimentemploying one or more of the disclosed substantially neutrally buoyantparticulate materials and a brine carrier fluid, mixing equipment needonly include such equipment that is capable of (a) mixing the brine(dissolving soluble salts), and (b) homogeneously dispersing in thesubstantially neutrally buoyant particulate material. In one embodiment,a substantially neutrally buoyant particulate/proppant material may beadvantageously pre-suspended and stored in a storage fluid, such asbrine of near or substantially equal density, and then pumped or placeddownhole as is, or diluted on the fly.

Examples of non-natural porous particulate materials for use in theinvention include, but are not limited to, porous ceramic particles suchas those particles available from Carbo Ceramics Inc. as “Econoprop”,and those fired kaolinitic described in U.S. Pat. No. 5,188,175 which isincorporated herein by reference. As described in this reference suchparticles may include solid spherical pellets or particles from rawmaterials (such as kaolin clay) having an alumina content of betweenabout 25% and 40% and a silica content of between about 50% and 65%. Astarch binder may be employed. Such particles may be characterized ashaving a ratio of silicon dioxide to alumina content of from about 1.39to about 2.41, and an apparent specific gravity of between about 2.20and about 2.60 or between about 2.20 and about 2.70.

It will also be understood that porous ceramic particles may beselectively manufactured from raw materials such as those described inU.S. Pat. No. 5,188,175; U.S. Pat. No. 4,427,068; and U.S. Pat. No.4,522,731, which are each incorporated herein by reference, such as byinclusion of selected process steps in the initial materialmanufacturing process to result in a material that possesses desiredcharacteristics of porosity, permeability, apparent density or apparentspecific gravity, combinations thereof. For example, such raw materialsmay be fired at relatively low temperature of about 1235° F. or about1300° F. (or about 700° C.) to achieve a desired crystalline structureand a more highly porous and lighter structure. In one exemplaryembodiment of such particles, as described elsewhere herein, about 20/40mesh size porous material fired kaolinitic particles from Carbo CeramicsInc. may be selected for use in the disclosed method. These particleshave the following internal characteristics: bulk apparent density about1.16, internal porosity about 59.3%. These particles may be treated witha variety of penetrating/coating materials in an amount of from about0.5 to about 10% by total weight of particle. Such coated particles maybe manufactured and/or supplied, for example, by Fritz Industries ofMesquite, Tex.

In one exemplary case, size of such a material may be selected to rangefrom about 200 mesh to about 8 mesh.

In such a case, the particles may be selected based on porosity and/orpermeability characteristics so that they have desired lightweightcharacteristics, such as when suspended in a selected carrier fluid fora well treatment. As before, the inherent and/or induced porosity of aporous material particle may be selected so as to help provide thedesired balance between apparent density and strength. Optionalmaterials may be employed along with a glazing, penetrating and/orcoating material to control penetration such as enhance or impairpenetration. For example, in one embodiment an cationic clay stabilizer,such as CLAY MASTER 5C from BJ Services, may be first applied to theexterior surface of a porous ceramic material to inhibit penetration bycoating/penetrating material, such as epoxy or resin described elsewhereherein.

In a selectively configured porous particulate material, the porousparticulate material is chemically treated in order to impart desiredphysical properties, such as porosity, permeability, apparent density orapparent specific gravity, or combinations thereof to the particulatematerials. Such desired physical properties are distinct from thephysical properties of the porous particulate materials prior totreatment.

The desired physical properties may further be present innon-selectively configured porous particulate materials. Non-selectivelyconfigured porous particulate materials shall include naturallyoccurring porous ceramic materials as well as non-natural (synthetic)materials manufactured in a manner that renders such desiredcharacteristics.

The non-selectively configured particulate material is selected based ondesired physical properties, such as porosity, permeability, apparentdensity, particle size, chemical resistance or combinations thereof.

The selectively configured porous particulate material as well asnon-selectively configured porous particulate material exhibit crushresistance under conditions as high as 10,000 psi closure stress, API RP56 or API RP 60, generally between from about 250 to about 8,000 psiclosure stress, in combination with a apparent specific gravity lessthan or equal to 2.4, to meet the pumping and/or downhole formationconditions of a particular application, such as hydraulic fracturingtreatment, sand control treatment.

Such desired physical properties may be imparted to a portion orportions of the porous particulate material of the selectivelyconfigured porous particulate material or non-selectively configuredporous particulate material, such as on the particle surface of thematerial particulate, at or in the particle surface of the particulatematerial, in an area near the particle surface of a particulatematerial, in the interior particle matrix of a particulate material or aportion thereof, combinations thereof, etc.

Advantageously, in one embodiment the low apparent specific gravity ofthe porous particulate material of the selectively configured porousparticulate material or non-selectively configured porous particulatematerial may be taken advantage of to result in a larger fracture orfrac pack width for the same loading, such as pound per square foot ofproppant, to give much larger total volume and increased width for thesame mass. Alternatively, this characteristic allows for smaller loadingof proppant material to be pumped while still achieving an equivalentwidth.

In a preferred embodiment, selective configuration, such as by usingglaze-forming, coating and/or penetrating materials, such as thosematerials described elsewhere herein, may be selectively employed tomodify or customize the apparent specific gravity of a selected porousparticulate material. Modification of particulate apparent specificgravity, to have a greater or lesser apparent specific gravity, may beadvantageously employed, for example, to provide proppant or sandcontrol particulates of customized apparent specific gravity for use asa substantially neutrally buoyant particulate with a variety ofdifferent weight or apparent specific gravity carrier fluids.

The selectively configured porous particulate material has an apparentdensity from about 1.1 g/cm³ to about 2.6 g/cm³, a bulk apparent densityfrom about 1.03 g/cm³ to about 1.5 g/cm³, and an internal porosity fromabout 10 to about 75 volume percent. In one example, bulk densities maybe controlled to be in the range of from about 1.1 g/cm³ to about 1.5g/cm³, although greater and lesser values are also possible.

The selectively configured porous particulate material, as well as thenon-selectively configured particulate material, is generally betweenfrom about 200 mesh to about 8 mesh.

The selectively configured porous particulate material may compriseporous particulate material selectively altered by treating with acoating or penetrating material using any suitable wet or dry process.Methods for coating particulates, such as fracture proppant particles,with materials such as resin are known in the art, and such materialsare available, for example, from manufacturers listed herein. Withregard to coating of the disclosed porous particulate materials, coatingoperations may be performed using any suitable methods known in the art.

As used herein, the term “penetration” shall further refer to partiallyor completely impregnated with a penetrating material, by for example,vacuum and/or pressure impregnation. For example, porous particulatematerial may be immersed in a second material and then exposed topressure and/or vacuum to at least partially penetrate or impregnate thematerial.

Those of skill in the art will understand that one or more coatingand/or penetrating materials may be selected to treat a porous materialparticulate to meet particular criteria or requirements of givendownhole application based on the information and examples disclosedherein, as well as knowledge in the art. In this regard, porous materialparticle characteristics, such as composition, porosity and permeabilitycharacteristics of the particulate material, size, and/or coating orpenetrating material characteristics, such as composition, amount,thickness or degree of penetration, may be so selected. The coating orpenetrating material is typically non-porous.

The porosity and permeability characteristics of the porous particulatematerial allows the penetrating material to be drawn at least partiallyinto the porous matrix of the porous particulate material by capillaryaction, for example, in a manner similar to a sponge soaking up water.Alternatively, one or more penetrating materials may be drawn at leastpartially into the porous matrix of the porous particulate materialusing a vacuum, and/or may be forced at least partially into the porousmatrix under pressure.

Examples of penetrating materials that may be selected for use include,but are not limited to, liquid resins, plastics, cements, sealants,binders or any other material suitable for at least partiallypenetrating the porous matrix of the selected particle to providedesired characteristics of strength/crush resistance, apparent specificgravity, etc. It will be understood that selected combinations of anytwo or more such penetrating materials may also be employed, either inmixture or in sequential penetrating applications.

Examples of resins that may be employed as penetrating and/or coatingmaterials include, but are not limited to, resins and/or plastics or anyother suitable cement, sealant or binder that once placed at leastpartially within a selected particle may be crosslinked and/or cured toform a rigid or substantially rigid material within the porous structureof the particle. Specific examples of plastics include, but are notlimited to, nylon, polyethylene, styrene, etc. and combinations thereof.Suitable resins include phenol formaldehyde resins, melamineformaldehyde resins, and urethane resins, low volatile urethane resins,such as these and other types of resins available from Borden ChemicalInc., Santrol, Hepworth of England, epoxy resins and mixtures thereof.Specific examples of suitable resins include, but are not limited to,resins from Borden Chemical and identified as 500-series and 700-seriesresins (e.g., 569C, 794C, etc.). Further specific examples of resinsinclude, but are not limited to, SIGMASET series low temperature curingurethane resins from Borden Chemical, such as SIGMASET, SIGMASET LV,SIGMASET XL, ALPHASET phenolic resin from Borden Chemical, OPTI-PROPphenolic resin from Santrol, and POLAR PROP low temperature curing resinfrom Santrol. Where desired, curing characteristics, such as curingtime, may be adjusted to fit particular treatment methods and/or finalproduct specifications by, for example, adjusting relative amounts ofresin components. Still further examples of suitable resins and coatingmethods include, but are not limited to, those found in European PatentApplication EP 0 771 935 A1; and in U.S. Pat. Nos. 4,869,960; 4,664,819;4,518,039; 3,929,191; 3,659,651; and 5,422,183, each of the foregoingreferences being incorporated herein by reference in its entirety.

In one exemplary embodiment, a curable phenolic resin or other suitablecurable material may be selected and applied as a coating material sothat individual coated particles may be bonded together under downholetemperature, after the resin flows and crosslinks/cures downhole, suchas to facilitate proppant pack/sand control particulate consolidationafter placement.

Alternatively, a cured phenolic type resin coat or other suitable curedmaterial may be selected to contribute additional strength to theparticles and/or reduce in situ fines migration once placed in asubterranean formation. The degree of penetration of the coating orpenetrating fluid into the porous particulate material may be limited bydisconnected porosity, such as substantially impermeable or isolatedporosity, within the interior matrix of the particulate.

This may either limit the extent of uniform penetration of penetratingmaterial in a uniform manner toward the core, such as leaving astratified particle cross section having outside penetrating layer withunpenetrated substantially spherical core, and/or may cause unevenpenetration all the way to the core, such as bypassing “islands” ofdisconnected porosity but penetrating all the way to the core. In anyevent, a penetrating and/or coating material may trap or encapsulate air(or other fluid having apparent specific gravity less than particlematrix and less than coating/penetrating material) within thedisconnected porosity in order to reduce apparent specific gravity bythe desired amount. Such materials coat and/or penetrate the porousparticulate without invading the porosity to effectively encapsulate theair within the porosity of the particle. Encapsulation of the airprovides preservation of the ultra-lightweight character of theparticles once placed in the transport fluid. If the resin coating ortransport fluids were to significantly penetrate the porosity of theparticle, the density increases accordingly, and the particle no longerhas the same lightweight properties. The resin coat also adds strengthand substantially enhances the proppant pack permeability at elevatedstress.

Coating layers may be applied as desired to contribute to particlestrength and/or reduce in situ fines migration once placed in asubterranean formation. The coating significantly increases the strengthand crush resistance of the ultra-lightweight ceramic particle. In thecase of natural sands the resin coat protects the particle fromcrushing, helps resist embedment, and prevents the liberation of fines.

The coating or penetrating fluid is typically selected to have anapparent specific gravity less than the apparent specific gravity of theporous particulate material so that once penetrated at least partiallyinto the pores of the matrix it results in a particle having a apparentspecific gravity less than that of the porous particulate material priorto coating or penetration, i.e., filling the pore spaces of a porousparticulate material results in a solid or substantially solid particlehaving a much reduced apparent density.

For example, the selected porous particulate material may be treatedwith a selected penetrating material in such a way that the resultantselectively configured porous particulate material has a much reducedapparent density, such as having a apparent density closer to orapproaching the apparent specific gravity of a carrier fluid so that itis neutrally buoyant or semi-buoyant in a fracturing fluid or sandcontrol fluid.

Alternatively, a penetrating material may be selected so that it helpsstructurally support the matrix of the porous particulate material(i.e., increases the strength of the porous matrix) and increases theability of the particulate to withstand the closure stresses of ahydraulic fractured formation, or other downhole stresses.

For example, a penetrating material may be selected by balancing theneed for low apparent density versus the desire for strength, i.e., amore dense material may provide much greater strength. In this regard,the inherent and/or induced porosity of the porous particulate materialmay be selected so as to help provide the desired balance betweenapparent density and strength. It will be understood that othervariable, such as downhole temperature and/or fluid conditions, may alsoimpact the choice of penetrating materials.

The coating layer or penetrating material is generally present in theselectively configured porous particulate material in an amount of fromabout 0.5% to about 10% by weight of total weight. The thickness of thecoating layer of the selectively configured porous particulate materialis generally between from about 1 to about 5 microns. The extent ofpenetration of the penetrating material of the selectively configuredporous particulate material is from less than about 1% penetration byvolume to less than about 25% penetration by volume.

Especially preferred results are obtained when the porous particulatematerial is a porous ceramic particle having an apparent density of 1.25or less and untreated porosity is approximately 60%. Such materials maybe treated with a coating material that does not penetrate the porousmatrix of the porous particulate material, or that only partiallypenetrates the porous matrix of the ceramic particulate material. Suchtreated ceramic materials may have an apparent density from about 1.1g/cm³ to about 1.8 g/cm³ (alternatively from about 1.75 g/cm³ to about 2g/cm³ and further alternatively about 1.9 g/cm³), a bulk apparentdensity from about 1.03 g/cm³ to about 1.5 g/cm³, and a treated internalporosity from about 45% to about 55%. However, values outside theseexemplary ranges are also possible.

As an example, a porous ceramic treated with about 6% epoxy has beenseen to exhibit a bulk apparent density of about 1.29 and a porosity ofabout 50.6%, a porous ceramic treated with about 8% epoxy exhibits abulk apparent density of about 1.34 and a porosity of about 46.9%, aporous ceramic treated with about 6% phenol formaldehyde resin exhibitsa bulk apparent density of about 1.32 and a porosity of about 51.8%, anda porous ceramic treated with about 8% phenol formaldehyde resinexhibits a bulk apparent density of about 1.20 and a porosity of about54.1%.

In this embodiment, a coating material or penetrating material may beselected to be present in an amount of from about 0.5% to about 10% byweight of total weight of individual particles. When present, thicknessof a coating material may be selected to be from about 1 to about 5microns on the exterior of a particle. When present, extent ofpenetration penetrating material into a porous material particle may beselected to be from less than about 1% penetration by volume to lessthan about 25% penetration by volume of the particle. It will beunderstood that coating amounts, coating thickness, and penetrationamounts may be outside these exemplary ranges as well.

Further, the porous particulate material may be at least partiallyselectively configured by glazing, such as, for example, surface glazingwith one or more selected non-porous glaze materials. In such a case,the glaze, like the coating or penetrating material, may extend orpenetrate at least partially into the porous matrix of the porousparticulate material, depending on the glazing method employed and/orthe permeability (i.e., connectivity of internal porosity)characteristics of the selected porous particulate material, such asnon-connected porosity allowing substantially no penetration to occur.For example, a selected porous particulate material may be selectivelyconfigured, such as glazed and/or coated with a non-porous material, ina manner so that the porous matrix of the resulting particle is at leastpartially or completely filled with air or some other gas, i.e. theinterior of the resulting particle includes only air/gas and thestructural material forming and surrounding the pores. Once again, theinherent and/or induced porosity of a porous material particle may beselected so as to help provide the desired balance between apparentdensity and strength, and glazing and/or coating with no penetration (orextension of configured area into the particle matrix) may be selectedto result in a particle having all or substantially all porosity of theparticle being unpenetrated and encapsulated to trap air or otherrelatively lightweight fluid so as to achieve minimum apparent specificgravity. In addition to sealing a particle, such as to seal air/gaswithin the porous matrix of the particle, such selective configuration,such as using glazing and/or coating materials, may be selected toprovide other advantages.

In a preferred embodiment, the porous particulate material, such as theabove-described fired kaolinitic particles, is manufactured by using aglaze-forming material to form a glaze to seal or otherwise alter thepermeability of the particle surface, so that a given particle is lesssusceptible to invasion or saturation by a well treatment fluid and thuscapable of retaining relatively lightweight or substantially neutrallybuoyant characteristics relative to the well treatment fluid uponexposure to such fluid. Such glazing may be accomplished using anysuitable method for forming a glaze on the surface or in the nearsurface of a particle, including by incorporating a glaze-formingmaterial into the raw material “green paste” that is then formed such asmolded into shape of the particle prior to firing. Those skilled in theart recognize that glazes may be made from a variety of methods,including the application of a smooth, glassy coating such that a hard,nonporous surface is formed. Glazes may be formed from powdered glasswith oxides. The mixture of powders is suspended in water and applied tothe substrate. The glaze can be dried and then fixed onto the substrateby firing or similar process known to those skilled in the art.Additionally, the use of borates or similar additives may improve theglaze.

Examples of such glaze-forming materials include, but are not limitedto, materials such as magnesium oxide-based material, boric acid/boricoxide-based material, etc. During firing, the glaze-forming material/s“bloom” to the surface of the particles and form a glaze. Alternatively,glazing may be accomplished, for example, by applying a suitableglaze-forming material onto the surface of the formed raw material or“green” particles prior to firing such as by spraying, dipping, andsimilar methods so that glazing occurs during particle firing. Furtheralternatively, a glaze-forming material may be applied to a firedceramic particle, and then fired again in a separate glaze-forming step.In one embodiment, the glaze forms a relatively hard and relativelynon-porous surface during firing of the particles.

Advantages of such a glazing treatment include maintaining therelatively low apparent density of a relatively lightweight porousparticle without the necessity of further alteration, such as necessityof coating with a separate polymer coating although optional coatingsmay be applied if so desired. Furthermore, the resulting relativelysmooth glazed surface of such a particle also may serve to enhance theease of multi phase fluid flow, such as flow of water and gas and oil,through a particulate pack, such as through a proppant pack in afracture, resulting in increased fracture conductivity.

In an alternative embodiment, one or more types of the disclosedselectively configured porous particulate material or non-selectivelyconfigured porous particulate material may be employed as particulatesfor well treating purposes in combination with a variety of differenttypes of well treating fluids (including liquid CO₂-based systems andother liquefied-gas or foamed-gas carrier fluids) and/or other types ofparticulates such as to achieve synergistic benefits, it beingunderstood that benefits of the disclosed methods and compositions mayalso be achieved when employing only one type of the disclosed porousmaterials as a sole well treating particulate. Furthermore, althoughexemplary embodiments are described herein with reference to porousmaterials and to relatively lightweight porous materials, it will beunderstood that benefits of the disclosed methods and compositions mayalso be realized when applied to materials that may be characterized asnon-relatively lightweight and/or non-porous in nature.

Elimination of the need to formulate a complex suspension gel may mean areduction in tubing friction pressures, particularly in coiled tubingand in the amount of on-location mixing equipment and/or mixing timerequirements, as well as reduced costs. Furthermore, when selectivelyconfigured, such as by glazing and/or by treating withcoating/penetrating material, to have sufficient strength and relativelightweight properties, the disclosed relatively particles may beemployed to simplify hydraulic fracturing treatments or sand controltreatments performed through coil tubing, by greatly reducing fluidsuspension property requirements. Downhole, a much reduced propensity tosettle (as compared to conventional proppant or sand controlparticulates) may be achieved, particularly in highly deviated orhorizontal wellbore sections. In this regard, the disclosed particulatematerial may be advantageously employed in any deviated well having anangle of deviation of between about 0 degree and about 90 degrees withrespect to the vertical. However, in one embodiment, the disclosedparticulate material may be advantageously employed in horizontal wells,or in deviated wells having an angle with respect to the vertical ofbetween about 30 degrees and about 90 degrees, alternatively betweenabout 75 degrees and about 90 degrees. Thus, use of the disclosedparticulate materials disclosed herein may be employed to achievesurprising and unexpected improvements in fracturing and sand controlmethodology, including reduction in proppant pack and/or formationdamage, and enhancement of well productivity.

It will be understood that the characteristics of glazing materials,penetrating materials and/or coating materials given herein, such ascomposition, amounts, types, are exemplary only. In this regard, suchcharacteristics may be selected with benefit of this disclosure by thoseof skill in the art to meet and withstand anticipated downholeconditions of a given application using methods known in the art, suchas those described herein.

In another disclosed embodiment, blends of two or more different typesof particles having different particulate characteristics, such asdifferent porosity, permeability, apparent density or apparent specificgravity, settling velocity in carrier fluid, may be employed as welltreatment particulates. Such blends may contain at least one porousparticulate material and at least one other particulate material thatmay or may not be a porous particulate material.

In addition, the selectively configured porous particulate material andnon-selectively configured porous particulate material may be used astwo or more multiple layers. In this regard, successive layers of suchmaterials may be employed. For instance, multiple layers may consist ofat least one selectively configured porous particulate material and atleast one non-selectively configured porous particulate material.

In one exemplary embodiment, a selected coating or penetrating materialmay be a urethane, such as ethyl carbamate-based resin, applied in anamount of about 4% by weight of the total weight of the selected porousmaterial particle. A selected coating material may be applied to achievea coating layer of at least about 2 microns thick on the exterior of theselected porous material particle.

Such blends may be further employed in any type of well treatmentapplication, including in any of the well treatment methods describedelsewhere herein. In one exemplary embodiment, such blends may beemployed to optimize hydraulic fracture geometries to achieve enhancedwell productivity, such as to achieve increased propped fracture lengthin relatively “tight” gas formations. Choice of different particulatematerials and amounts thereof to employ in such blends may be made basedon one or more well treatment considerations including, but not limitedto, objective/s of well treatment, such as for sand control and/or forcreation of propped fractures, well treatment fluid characteristics,such as apparent specific gravity and/or rheology of carrier fluid, welland formation conditions such as depth of formation, formationporosity/permeability, formation closure stress, type of optimizationdesired for geometry of downhole-placed particulates such as optimizedfracture pack propped length, optimized sand control pack height,optimized fracture pack and/or sand control pack conductivity andcombinations thereof.

Such different types of particles may be selected, for example, toachieve a blend of different specific gravities or densities relative tothe selected carrier fluid. For example, a blend of three differentparticles may be selected for use in a water fracture treatment to forma blend of well treatment particulates having three different specificgravities, such as apparent specific gravity of first type of particlefrom about 1 to less about 1.5; apparent specific gravity of second typeof particle from greater than about 1.5 to about 2.0; and apparentspecific gravity of third type of particle from about greater than about2.0 to about 3.0; or in one specific embodiment the three types ofparticles having respective specific gravities of about 2.65, about 1.7and about 1.2, it being understood that the preceding apparent specificgravity values are exemplary only and that other specific gravities andranges of specific gravities may be employed. In one example, at leastone of the types of selected well treatment particulates may be selectedto be substantially neutrally buoyant in the selected carrier fluid.

Such different types of particles may be selected for use in any amountsuitable for achieving desired well treatment results and/or costs.However, in one embodiment multiple types of particles may be selectedfor use in a blend of well treatment particulates in amounts that areabout equal in proportion on the basis of total weight of the blend.Thus, three different types of particles may each be employed inrespective amounts of about ⅓ of the total blend such as by total weightof the blend, four different types of particles may each be employed inrespective amounts of about ¼ of the total blend such as by total weightor the blend. However, these relative amounts are exemplary only, itbeing understood that any desired relative amount of each selected typeof well particulate may be employed, such as for one exemplaryembodiment of blend having three different types of particles, such asselected from the different types of particles described elsewhereherein, the amounts of each selected type of particle may be present inthe blend in an amount ranging from about 10% to about 40% such as bytotal weight of the blend to achieve 100% weight of the total blend.

It will be understood with benefit of this disclosure that choice ofdifferent particulate materials and amounts thereof to employ in suchblends may be made using any methodology suitable for evaluating suchblends in view of one or more desired well treatment considerations. Inone embodiment, any method known in the art suitable for modeling orpredicting sand control pack or fracture pack geometry/conductivity maybe employed, such as illustrated and described in relation to Example 4herein.

Examples of different particle types which may be selected for use insuch blends include, but are not limited to, conventional sandparticulates, such as Ottawa sand, relatively lightweight well treatmentparticulates, such as ground or crushed nut shells at least partiallysurrounded by at least one layer component of protective or hardeningcoating, selectively configured porous materials, such as any one ormore of the selectively configured porous materials described herein,such as deformable particles. Further examples of particle types whichmay be selected for use in such blends include any of those particlesdescribed in U.S. patent application Ser. No. 10/113,844, filed Apr. 1,2002; U.S. patent application Ser. No. 09/579,146, filed May 25, 2000;U.S. Pat. No. 6,364,018; U.S. Pat. No. 6,330,916; and U.S. Pat. No.6,059,034, each of which is incorporated herein by reference.

In one exemplary embodiment, selected blends of conventional sandproppant, relatively lightweight particulates of ground or crushed nutshells at least partially surrounded by at least one layer component ofprotective or hardening coating, and selectively configured porousmaterials such as relatively lightweight porous material firedkaolinitic particles treated with a penetrating/coating materialsdescribed herein may be employed in a hydraulic fracture treatmentutilizing ungelled or weakly gelled carrier fluid. One specific exampleof such a blend is described in Example 4 herein. In such an embodiment,these different types of particles may be employed in any relativevolume or weight amount or ratio suitable for achieving desired welltreatment results.

In one specific example, these different types of particles may beemployed in a well treatment particulate composition including about ⅓by weight of conventional sand proppant by total weight of welltreatment particulate, about ⅓ by weight of relatively lightweightparticulate, such as core of ground or crushed nut shells at leastpartially surrounded by at least one layer component of protective orhardening coating) by total weight of well treatment particulate, andabout ⅓ by weight of selectively configured relatively lightweightporous material, such as fired kaolinitic particles treated with apenetrating/coating materials described herein, by total weight of welltreatment particulate. It will be understood that the foregoing relativeamounts are exemplary only and may be varied, for example, to achievedesired results and/or to meet cost objectives of a given treatment. Itwill also be understood that the disclosed methods and compositions mayalso be practiced with such blends using other types of relativelylightweight particulate materials as described elsewhere herein, such asporous polymeric materials, such as polyolefins, styrene-divinylbenzenebased materials, polyalkylacrylate esters and modified starches.Further, any of the disclosed porous materials may be employed in “neat”or non-altered form in the disclosed blends where apparent density andother characteristics of the particle are suitable to meet requirementsof the given well treating application.

In one respect, disclosed are well treating methods, such as hydraulicfracturing and sand control, which may be employed to treat a wellpenetrating a subterranean formation, and include introducing into awell a selected porous particulate material that is treated with aselected coating material, selected penetrating material, or combinationthereof. Individual particles of the particulate material optionally mayhave a shape with a maximum length-based aspect ratio of equal to orless than about 5. In one embodiment porous particulate materials may beany particulate material with suitable internal porosity and/orpermeability characteristics to achieve the desired finished particleproperties when combined with selected penetrating/coating materials asdescribed elsewhere herein.

Examples of suitable porous material particulates that may be selectedfor use in aqueous based carrier fluids include, but are not limited toporous ceramics, porous polymeric materials or any other porous materialor combinations thereof suitable for selection for combination ofinternal porosity and permeability to achieve desired properties, suchas strength and/or apparent specific gravity, for particular downholeconditions and/or well treatment applications as described elsewhereherein. For example, porous ceramic particles may be manufactured byfiring at relatively low temperatures to avoid loss of porosity due tocrystallization and driving off of water. Particular examples include,but are not limited to, porous ceramic particles available from CarboCeramics Inc. of Irving, Tex. composed of fired kaolinitic clay that isfired at relatively low temperature of about 1235° F. or about 1300° F.(or about 700° C. and that has trace amounts of components such ascristobalite, mullite and opalite), polyolefin particles, and similarcomponents.

In another disclosed embodiment, relatively lightweight particulates orblends including such particulates as described elsewhere herein, suchas including selectively configured particulates and/or non-selectivelyconfigured particulates described elsewhere herein, may beadvantageously employed as well treatment particulates, such as fractureproppant particulate or sand control particulate, in liquefied gas andfoamed gas carrier fluids.

Examples of types of such carrier fluids include, but are not limitedto, liquid CO₂-based systems, liquid CO₂, CO₂/N₂, and foamed N₂ in CO₂systems that may be employed in hydraulic fracturing applications. Inone specific embodiment, porous ceramic well particulates having a bulkapparent density of close to or about 1.0 g/cm³, in either selectivelyconfigured or non-selectively configured form, may be employed with suchliquefied gas and/or foamed gas carrier fluids, such as liquid CO₂-basedsystems, liquid CO₂, CO₂/N₂, and foamed N₂ in CO₂ systems. In anotherspecific embodiment, selectively configured particulates and/ornon-selectively configured particulates may be employed that may becharacterized as substantially neutrally buoyant in such liquefied gasand/or foamed gas carrier fluids.

Liquid CO₂ has a density close to about 1.02 g/cm³ under typicalfracturing conditions, and conventional proppants, such as sand, ornon-relatively lightweight ceramic proppants have a tendency to settlein liquid CO₂-based systems. Furthermore, liquid CO₂ has very little ifany viscosity, and therefore proppant transport in a liquid CO₂-basedsystem is provided by turbulence and frictional forces, and fracturescreated by liquid CO₂ are typically relatively narrow. Advantageously,using the disclosed methods and compositions, proppant transport ofrelatively lightweight particulates is easier than is proppant transportof conventional sand proppants or non-relatively lightweight ceramicproppants.

In one exemplary embodiment, relatively lightweight porous ceramicparticles may be employed in liquid CO₂-based systems. Examples of typesof such relatively lightweight porous ceramic particles include, but arenot limited to, those porous ceramic particles available from CarboCeramics for controlled release applications altered in themanufacturing process to have a bulk apparent density close to about 1.0g/cm³. Other suitable examples of relatively lightweight porousparticles include, but are not limited to, those particles having a bulkapparent density of less than about 2.5 g/cm³, alternatively having abulk apparent density of from about 1.0 to about 2.0 g/cm³, furtheralternatively having a bulk apparent density of from about 1.2 g/cm³ toabout 2.0 g/cm³.

One specific example of suitable relatively lightweight porous ceramicparticle for use in CO₂-based systems of this embodiment is porousceramic material described elsewhere herein, either in selectivelyconfigured form, as described herein in Example 1, or in non-selectivelyconfigured or non-altered or “neat” form.

In one exemplary embodiment, the practice of the disclosed methods andcompositions, relatively lightweight porous ceramic materials or blendsthereof may be employed as fracture proppant materials in liquidCO₂-based fracturing systems using methodologies similar or the same tothose employed with conventional proppants in liquid CO₂-basedfracturing systems. In this regard, liquid CO₂-based fracturing jobcharacteristics, such as proppant amounts, proppant sizes, mixing andpumping methodologies, using relatively lightweight porous ceramicmaterials may be the same as described for conventional proppants in“The History and Success of Liquid CO₂ and CO₂/N₂ Fracturing System” byGupta and Bobier, SPE 40016, March 1998. Further information on liquidCO₂-based fracturing job characteristics that may be employed withrelatively lightweight porous ceramic materials may be found in U.S.Pat. No. 4,374,545, U.S. Pat. No. 5,558,160, U.S. Pat. No. 5,883,053,Canadian Patent No. 2,257,028 and Canadian Patent No. 2,255,413, each ofthe foregoing references being incorporated herein by reference.

In one disclosed exemplary embodiment, relatively lightweight porousceramic particles employed as fracture proppant particulate in a liquidCO₂-based system may be used in “neat” or non-altered form and may havea apparent specific gravity of from about 1.17 to about 2.0 In anotherdisclosed exemplary embodiment, using relatively lightweight porousceramic particles as fracture proppant particulate in a liquid CO₂-basedsystem allows the concentration of proppant in such a system to beadvantageously extended to about 1200 Kg/cubic meter. Other advantagesof using the disclosed relatively lightweight porous ceramic particlesin liquid CO₂-based fracturing systems include, but are not limited to,reduced proppant settling in surface mixing equipment prior to pumpingdownhole and improved proppant transport downhole and into theformation. It will be understood that although described above forembodiments employing relatively lightweight porous ceramic particles,the disclosed methods and compositions may also be practiced with liquidCO₂-based systems using other relatively lightweight porous materialparticulate materials and blends thereof described elsewhere herein,such as porous polymeric materials such as polyolefins. Any of suchmaterials may be employed in “neat” or non-altered form with liquidCO₂-based systems where apparent density and other characteristics ofthe particle are suitable to meet requirements of the given welltreating application, or may alternatively be employed in selectivelyconfigured form as described elsewhere herein.

The following examples will illustrate the practice of the presentinvention in a preferred embodiment. Other embodiments within the scopeof the claims herein will be apparent to one skilled in the art fromconsideration of the specification and practice of the invention asdisclosed herein. It is intended that the specification, together withthe example, be considered exemplary only, with the scope and spirit ofthe invention being indicated by the claims which follow.

EXAMPLES

The following examples are illustrative and should not be construed aslimiting the scope of the invention or claims thereof.

Example 1

To obtain the data for this example, the following procedure wasfollowed: Measured mass of 25 ml of sample on a graduate cylinder.Cylinder was tapped several times on the countertop and the volumeadjusted to an even 25 ml prior to weighing. Mass/volume=bulk density.

The data of this example is shown in Table 1:

TABLE 1 Bulk Densities Sand 1.721 CarboLite 1.747 Porous Ceramic - Neat1.191 Porous Ceramic - 2/2 1.238 Porous Ceramic - 6% 1.293 PorousCeramic - 8% P-A 1.224 Porous Ceramic - 8% P-B 1.198 Porous Ceramic -10% P 1.32FIG. 1 illustrates comparisons of the bulk densities of variousproppants/sand control materials to samples of a selected porous ceramicmaterial (from Carbo Ceramics, Inc.).

In the examples, “Carbolite” is a commercial proppant available fromCarbo Ceramics, Inc. “Neat” is untreated porous ceramic material fromCarbo Ceramics, Inc., “ 2/2” is porous ceramic material from CarboCeramics, Inc. treated with 2% by weight of particle epoxy innercoating/penetrating material (epoxy is reaction product ofepichlorohydrin and bis-phenol A) and with 2% by weight of particlephenol formaldehyde resin outer coating material, “6%” is porous ceramicmaterial from Carbo Ceramics, Inc. treated with 6% by weight of particlecoating/penetrating material (epoxy is reaction product ofepichlorhidian and bis-phenol A), “8% P-A” is porous ceramic materialfrom Carbo Ceramics, Inc. treated with 8% by weight of particle phenolformaldehyde resin (Sample A), “8% P-B” is porous ceramic material fromCarbo Ceramics, Inc. treated with 8% by weight of particle phenolformaldehyde resin (Sample B), and “10% P” is porous ceramic materialfrom Carbo Ceramics, Inc. treated with 10% by weight of particle phenolformaldehyde resin.

Data is presented for both the untreated porous material particle, andfor the porous material particle treated with various types andconcentrations of selected penetrating materials. As may be seen, thebulk apparent density of the resulting particles varies with varyingdegree of infiltration or penetration of the penetrating material intothe porous ceramic particle. The samples designated as 2/2 and 8% P-Bmay be characterized from SEM thin section analysis as having limitedpenetration towards the core of the particle, apparent effectiveencapsulation of the air in the particle core porosity, yet substantialenhancement of the particle strength as illustrated by the conductivitytests.

FIGS. 2 and 5 illustrate the permeability versus closure stress forcoated and uncoated ceramic ULW particulates. As shown, resin coatingand impregnation of the ULW particle imparts significant strength acrossthe closure range and in particular, enhances the low to mid-rangeperformance of the material. The data represents equal pack widths forall of the proppants with adjustments made for each respective density.Both the coated and uncoated ceramics ULW were tested at 1.4 pounds persquare foot (33.2 kg/m²). Each of these tests had nearly identical widthmeasurements for ease of comparison.

Example 2

The porous particulate material employed was from “Carbo Ceramics”having a size of about 20/40 mesh. The particulate material was treatedwith various penetrating/coating materials corresponding to the sameepoxy or phenol formaldehyde materials used above. The treatedparticulate material was tested alone, with no other particulatematerial blended in. Comparison materials include Jordan Sand,“Econoprop” proppant from Carbo Ceramics, “Econoflex” (coated Econopropproppant), Hickory sand (Brady Sand), “PR6000” 2% coated Ottawa sandfrom BORDEN, and “Carbolite” proppant from Carbo Ceramics.

Conductivity tests were performed according to API RP 61 (1^(st)Revision, Oct. 1, 1989) using an API conductivity cell with Ohiosandstone wafer side inserts. Each particulate material sample wasloaded into the cell and closure stress applied to the particulatematerial using a “DAKE” hydraulic press having a “ROSEMOUNT”differential transducer (#3051C) and controlled by a “CAMILE”controller. Also employed in the testing was a “CONSTAMETRIC 3200”constant rate pump which was used to flow deionized water through eachparticulate sample.

Table 2 shows the proppant pack Permeability and Conductivity datagenerated for this example.

TABLE 2 Porous Ceramic Worksheet PC - 4% PC - 6% PC - 8% PC - 2% PC - 6%PC - 8% PC neat Epoxy epoxy epoxy &2% resin resin Bulk Dens 1.198 1.2921.34 1.238 1.293 1.224 Acid 5.7% Solubility Porosity 50.2% 46.9% 51.8%54.1% Crush 2000 3.65 3000 4000 7.52 4.54 5000 6000 16.88 16.36 700021.00 7500 8000 20.87 10000  PC 10% 20/40 20/40 20/40 20/40 20/40 20/40resin Jordan Econoprop Econoflex Hickory PR 6000 Carbolite Bulk Dens1.32 1.6 1.6 1.5 1.6 1.54 1.6 Acid 1.20% 1.90% 0.30% 0.50% 0.30% 1.70%Solubility Porosity Crush 2000 .1 0.4 0.1 3000 .3 1.8 0.2 4000 1.6 0.19.8 0.4 5000 2.6 13.6 0.7 6000 0.1 1.9 7000 7500 4.7 3.1 1.5 8000 0.24.5 10000  13.3 0.5 10.7 12.1 PC PC 4% PC - 6% PC - 8% PC - 2% PC - 6%PC - 8% Permeability neat Epoxy epoxy epoxy &2% resin resin 2000 149 425322 409 406 559 1193 3000 110 331 226 304 318 376 994 4000  70 237 130190 230 192 786 5000  97 110 131 185 151 671 6000 64 89 142 110 546 700048 55 78 361 8000 28 44 46 175 PC - 10% 20/40 20/40 20/40 20/40 20/4020/40 Permeability resin Jordan Econoprop Econoflex Hickory PR 6000Carbolite 2000 508 228 342 287 224 275 500 3000 384 170 319 274 144 241466 4000 260 113 295 262 64 208 433 5000 181 80 257 255 42 168 376 6000101 47 220 248 21 127 319 7000 32 178 225 12 94 252 8000 18 135 202 4 61186 PC - #1 PC - 4% PC - 6% PC - 8% PC - 2% PC - 6% PC - 8% Conductivityneat Epoxy epoxy epoxy &2% resin resin 2000 2726 8436 4693 5965 54844658 13522 3000 1915 5152 3194 4283 4053 3177 10275 4000 1103 1868 16952600 2621 1695 7028 5000 949 1356 1616 1983 1221 5406 6000 747 1042 1345747 3783 7000 526 604 522 2455 8000 296 463 296 1127 PC - 10% 20/4020/40 20/40 20/40 20/40 20/40 Conductivity resin Jordan EconopropEconoflex Hickory PR 6000 Carbolite 2000 5760 2116 3423 2586 2020 25504755 3000 4116 1564 3132 2382 1276 2201 4383 4000 2472 1013 2842 2178532 1852 4011 5000 1729 709 2442 2036 344 1468 3445 6000 986 405 20421895 157 1085 2879 7000 279 1621 1650 94 790 2255 8000 154 1201 1405 31495 1637

Data is presented graphically in FIGS. 2-6.

Conductivity is a function of the width times the permeability.Advantageously, as disclosed herein in one embodiment, a selected porousmaterial particulate may be treated with a selected coating and/orpenetrating material to produce a relatively lightweight particulatesample that at the same 1 b/sq ft loading as a conventional sand willoccupy a greater width. Even if the pack permeability is the same, theconductivity, and thus the proppant pack producibility, will be higher.Thus, as represented by the conductivity data, the benefit of thecombination of increased width and the improved permeability may beachieved. Further, as disclosed herein in one embodiment, a selectedporous material particulate may be treated with a selected coatingand/or penetrating material so that particle strength is maintained toas high a confining (or closure) stress as possible, which is reflectedmore directly by the permeability data. Thus a certain amount offracture conductivity at a given stress/temp condition may be maintainedwithout increasing the cost, and/or by offsetting any cost increase withimproved value. Even in the event of increased particulate materialcost, substantially less particulate material may be employed to achievea substantially equivalent conductivity due to the lesser mass/unitvolume.

Example 3

Using the selected treated material of the Examples above, particles maybe produced that are capable for use, such as having sufficient crushresistance for use or do not crush, under conditions of 2000 psi closurestress or greater, alternatively 2500 psi closure stress or greater,alternatively 3000 psi closure stress or greater, alternatively up to atleast about 6000 psi closure stress, alternatively up to at least about7000 psi closure stress, and alternatively at least about 8000 psiclosure stress, i.e., almost as resistant to crush as commercial ceramicproppants which are heavier (e.g., commercial ceramic proppant(CarboLite) is about 40% heavier). In another embodiment, particles maybe produced that are capable for use (e.g., have sufficient crushresistance for use or do not crush) under conditions of from about 2000psi closure stress to about 8000 psi closure stress, alternatively fromabout 2500 psi closure stress to about 8000 psi closure stress,alternatively from about 3000 psi closure stress to about 8000 psiclosure stress. However, it will be understood that particles mayproduced that are capable of use at higher closure stresses than 8000psi and lower closure stresses than about 2000 psi as well.

FIGS. 8-15 are cross-sectional and surface SEM photographs of varioustreated and untreated samples of porous ceramic materials from CARBOCERAMICS. Where indicated as “epoxy” or as “resin”, the particularcoating/penetrating material is either the same epoxy or phenolformaldehyde resin employed and identified in Example 1.

FIG. 8 shows particles treated with about 10% by weight of particleresin. FIG. 9 shows particles treated first with 2% by weight epoxy andsecond with 2% by weight resin. FIG. 10 shows untreated particles. FIG.11 shows particles treated first with 2% by weight epoxy and second with2% by weight resin. FIG. 12 shows surface of untreated particle. FIG. 13shows untreated particles. FIG. 14 shows particles treated with 8% byweight epoxy. FIG. 15 shows particles treated with 6% by weight epoxy.

Example 4

In this example, a selected blend of three different apparent specificgravity well treatment particulates were evaluated for use in a waterfracture treatment of a “tight” gas well based on a Canyon Sand gaswell. The three different apparent specific gravity particulates werechosen to represent, for example, a selected blend of the followingdifferent types of well treatment particulates:

-   -   I. 20/40 mesh Ottawa sand having the following properties:        apparent specific gravity of 2.65; Vt=17.5 ft/min @ Nre=+/−500        (Typical for water fracs)    -   II. 20/40 mesh porous ceramic particles coated with 2% resin        (described elsewhere herein) having the following properties:        apparent specific gravity of 1.70; Vt=9.5 ft/min @ Nre=+/−500        (Typical for water fracs)    -   III. 20/40 mesh ground or crushed nut shells coated with        protective or hardening coating (e.g., “LiteProp” from BJ        Services described in U.S. Pat. No. 6,364,018 and U.S. patent        application Ser. No. 09/579,146, each incorporated herein by        reference) having the following properties: apparent specific        gravity of 1.20; Vt=3.9 ft/min @ Nre=+/−500 (Typical for water        fracs)

As may be seen from the data above, particulate III weighs about half asmuch as Particulate I, but settles at a rate less than about ¼ as fast.

A well treatment particulate including a selected blend of roughly equalamounts of the above types of particulates (i.e., about ⅓ by weight ofabove particulate I of the total weight of the blend, about ⅓ by weightof above particulate II of the total weight of the blend, and about ⅓ byweight of above particulate III of the total weight of the blend) wasmodeled for use in a water fracture treatment of a “tight” gas wellusing a hydraulic fracture simulation program. FIG. 16 illustratesproppant distribution in the resulting simulated hydraulic fracturecreated downhole.

For comparison purpose, a well treatment particulate including onlyparticulate I (Ottawa sand) was modeled for use in a water fracturetreatment of the same “tight” gas well similarly modeled using the samepumping schedule (but in this case using 135,000 pounds of Ottawa sand).FIG. 17 illustrates proppant distribution in the resulting simulatedhydraulic fracture created downhole.

As may be seen from a comparison of the resulting propped profiles ofFIGS. 16 and 17, the well treatment particulate including onlyparticulate I (Ottawa sand) resulted in a proppant distribution thatpropped the bottom half of the pay out to about 1000′ (see FIG. 17),while the well treatment particulate including a selected blend ofroughly equal amounts of particulates I, II and III resulted in asynergistic proppant distribution that propped all of the pay out toalmost 2000′ (see FIG. 16), or approximately four times the proppedfracture surface area.

Example 5

The proppant distributions of FIG. 16 and FIG. 17 were next input into areservoir production simulator (“M-Prod”) and gas production separatelysimulated for each proppant distribution. An assumption was made thatthe effective conductivity of the proppant distribution of FIG. 16(i.e., roughly equal amounts of particulates I, II and III) would haveonly 1/10^(th) the effective conductivity of the proppant distributionof FIG. 17 (i.e., particulate I only). The proppant distribution of FIG.17 (i.e., particulate I only) produced at an initial potential of 707MCFD with a cumulative production of 595 MMCF over ten years, while theproppant distribution of FIG. 16 (i.e., roughly equal amounts ofparticulates I, II and III) produced at an initial potential of 920mcf/day (“MCFD”) with a cumulative production of 1312 MMCF over tenyears. Thus, the proppant distribution of FIG. 16 (i.e., roughly equalamounts of particulates I, II and III) resulted in the production oftwice the reserves from the same well as the proppant distribution ofFIG. 17( i.e., particulate I only), despite having only 1/10^(th) ofassumed conductivity. This shows how the disclosed selected blend ofdifferent types of well treatment particulates may be advantageouslyemployed to achieve increased production rates and reserves fromrelatively tight gas formations by increasing propped fracture lengths,even with reduced effective conductivities.

Although this example illustrates the use of a selected blend ofdifferent types and amounts of well treatment particulates in a tightgas well, it will be understood that blends of these and other types ofwell treatment blends may be selected and employed for other types ofwells, including wells productive of liquids as well as gas, and wellshaving relatively higher formation permeability values. Furthermore, itwill be understood that benefits of the disclosed method may be realizedusing blends of other than three different types of well treatmentparticulates, for example, using two different types of well treatmentparticulates or more than three different types of well treatmentparticulates (e.g., as many as four, five, six, seven, eight, nine andmore different types of well treatment particulates) having varyingcharacteristics.

Example 6

ULW-1.75 corresponds to 2/2 discussed above in Example 1 and can becharacterized as a porous ceramic particle with the roundness andsphericity common to ceramic proppants. The porosity averages 50%,yielding a bulk density of 1.10 to 1.15 g/cm³. Median-sized 20/40particles of the ULW-1.75 and Ottawa sand were used. The 20/40 Ottawasand has an average bulk density of 1.62 g/cm with a specific gravity of2.65. The ULW-1.75 has a bulk density of 1.05 to 1.10.

Static particle settling evaluations were conducted in fresh water todetermine the differences in settling rate between the conventionalproppant and the ULW particles. Median sized 20/40 particles of eachproppant were used for the evaluations. Stokes Law calculations givingthe fall velocity in ft/minute are presented in Table 3 and werecalculated as:

V=1.15×10³(d ² _(prop)/μ_(fluid))(Sp.Gr. _(Prop) −Sp.Gr. _(fluid))

where velocity is in ft/min., diameter d is the average particlediameter and, μ is fluid viscosity in cps.

TABLE 3 Static Settling Rates for Proppants as Derived by Stoke's Law20/40 Proppant Sp. Gr. Settling Velocity ft/minute Ottawa sand 2.65 16.6ULW-1.75 1.75 11.2

Large-scale slot flow tests were conducted to characterize the dynamicsettling rates of the ultra-lightweight proppant. Proppant transportcharacteristics were studied at ambient temperature through a glassslot. The transparent slot is a 22-inch high, 16-ft long and 0.5-inchwide parallel plate device. One thousand gallons of test fluid wasprepared and the fluid rheology was measured using a standard Fann 35viscometer. Fluid was then transferred to a 200-gallon capacity ribbonblender and pumped through the test loop to fill the transparent slotmodel. Once the slot was filled with the test fluid, proppant was addedto the blender to prepare a slurry of the desired concentration. Theslickwater fluid used in the test exhibited an average viscosity of 5 to7 cps throughout the series of tests.

The shear rate in the slot is given by the equation:

$\gamma = {\lbrack \sec^{- 1} \rbrack = \frac{1.925\; {q\lbrack{gpm}\rbrack}}{( {w\lbrack {{in}.} \rbrack} )^{2}( {H\lbrack{ft}\rbrack} }}$

where q is the rate in gallons per minute, w is width in inches and H isheight in feet. Fluid velocity through this slot model is given by:

${v\lbrack {m\text{/}\sec} \rbrack} = \frac{0.00815\; {q\lbrack{gpm}\rbrack}}{( {w\lbrack {{in}.} \rbrack} )( {H\lbrack{ft}\rbrack} )}$

The proppant transport behavior of each test slurry was observed throughthe slot at various flow rates. During these tests, the proppantdistribution was continually recorded with video cameras as well asmanually by observation. All bed height measurements for this work weretaken close to the discharge end of the slot flow cell.

Ottawa sand slurried in slickwater was observed to begin settling uponentrance to the slot even at the maximum fluid pump rate. Within 12minutes at 90 gpm (378 sec-1 shear rate), the bed height was 15 inches,68% of the total height of the 22 in. slot. Table 4 below shows theresults in tabular form. Only at shear rates in excess of 1000 sec-1 wasthe dynamic Ottawa Sand proppant fall rate mitigated in the slickwatertest fluid. As flow rates were lowered to 30 gpm, the Ottawa proppantbed reached its maximum bed height of 19.5 inches or 91.25% of the slotheight. Above the proppant bed, the shear rate reached 1,414 sec-1, atwhich point additional settling did not occur. As the rate increasedfrom 30 to 40 gpm (1,919 sec-1), the bed height was actually reduced.

TABLE 4 Time, Fluid Rate Prop Bed Slot Shear Above bed, minute GpmHeight (ft) Sec-1 sec-1 0 90 0 378 378 1 90 0.25 383 443 12 90 1.25 3811201 14 60 1.27 252 825 18 60 1.38 252 825 19 40 1.39 168 677 28 40 1.54170 1076 30 30 1.58 116 858 42 30 1.67 171 1414 43 40 1.67 171 1919 4540 1.52 169 1070

The ULW-1.75 test was initiated at 90 gpm. ULW-1.75 was observed to besubject to some settling at 90 gpm, with the bed height growing to 4inches. The fluid rate was lowered to 80 gpm and bed height grew to 6inches. As the rates were reduced incrementally down to 30 gpm, theULW-1.75 bed was observed to grow with reduced rate to 12 inches. Therate was lowered further to 5 gpm and the bed height grew to 19 inchesor 86% of the total slot height. As observed in previous tests, as therate is increased incrementally, bed height decreases due to erosion andfluidization of the bed. The ULW-1.75 results are presented in Table 5.

TABLE 5 Time, Fluid Rate Prop Bed Slot Shear Above bed, minute GpmHeight Sec-1 sec-1 0 90 0.0 378 378 7 90 0.33 378 463 8 80 0.38 337 42311 80 0.54 337 478 12 70 0.58 295 432 15 60 0.71 252 412 17 60 0.79 252445 18 50 0.83 210 386 20 50.4 0.92 212 425 22 39 0.96 164 345 23 30 1126 278 28 31 1.29 130 443 29 20 1.33 81 299 33 8 1.44 34 159 34 5.11.46 21 106 35 20 1.54 84 534 37 20.5 1.58 86 640 38 40.4 1.52 170 100640 50.6 1.46 213 1048 45 60.2 1.33 253 933

Both of the tested materials settle progressively more as the velocitydecreases. Due to the decreased density, the ULW is more easily placedback in flow as the rate is increased. The reduced density materialsrequire less shear increase to fluidize the proppant bed. Ottawa sandwas observed to require in excess of 1,500 sec-1 to transport theproppant in slickwater and almost 2,000 sec-1 of shear to begin tofluidize the proppant bed. The ULW-1.75 transporting at shear rates of500 sec-1 and fluid shear rates of 800 sec-1 were needed to fluidize theproppant bed.

The data clearly show the advantage of lower density particles inrelation to dynamic sand fall rates. Heavier proppants requiresignificant fluid viscosity, elevated fluid density, and/or high slurryvelocity for effective proppant transport.

While the invention may be adaptable to various modifications andalternative forms, specific embodiments have been shown by way ofexample and described herein. However, it should be understood that theinvention is not intended to be limited to the particular formsdisclosed. Rather, the invention is to cover all modifications,equivalents, and alternatives falling within the spirit and scope of theinvention.

From the foregoing, it will be observed that numerous variations andmodifications may be effected without departing from the true spirit andscope of the novel concepts of the invention.

1. A method for treating a well penetrating a subterranean formation,comprising introducing into the well a selectively configured porousparticulate material, wherein the selectively configured porousparticulate material is a porous particulate material having inherent orinduced permeability manufactured with a glazing material or treatedwith a penetrating layer, coating layer or glazing material and furtherwherein the apparent specific gravity (ASG) of the selectivelyconfigured porous particulate material is less than the ASG of theporous particulate material.
 2. The method of claim 1, wherein theporous particulate material is a relatively lightweight and/orsubstantially neutrally buoyant particulate.
 3. The method of claim 1,wherein the porous particulate material is a porous ceramic.
 4. Themethod of claim 1, wherein the amount of penetrating layer, coatinglayer or glazing material in the selectively configured porousparticulate material is between from about 0.5 to about 10% by weight.5. The method of claim 1, wherein the selectively configured porousparticulate material is a proppant/sand control particulate manufacturedwith a non-porous glazing material or treated with a non-porouspenetrating layer, coating layer or glazing material.
 6. The method ofclaim 1, wherein the porous particulate material is introduced or pumpedinto the well as a suspension in a carrier fluid and further wherein thedensity of the carrier fluid and porous particulate material is of nearor substantially equal density.
 7. The method of claim 1, wherein theselectively configured porous particulate material exhibits crushresistance under conditions from about 250 to about 8,000 psi closurestress.
 8. The method of claim 1, wherein the selectively configuredporous particulate material is a proppant and is introduced into thewell in a fracturing fluid and further wherein the method comprisesfracturing the subterranean formation.
 9. The method of claim 8, whereinthe selectively configured porous particulate material is introducedinto the well in a slickwater fracturing fluid.
 10. The method of claim1, wherein the porous particulate material is a porous ceramic having aporosity and permeability such that either a fluid may be drawn at leastpartially into its porous matrix by capillary action or a penetratingmaterial may be drawn at least partially into its porous matrix using avacuum and/or may be forced at least partially into its porous matrixunder pressure.
 11. The method of claim 1, wherein the selectivelyconfigured porous particulate material is coated or penetrated with aliquid resin, plastic, cement, sealant, or binder.
 12. The method ofclaim 1, wherein the selectively configured porous particulate materialis coated or penetrated with a phenol, phenol formaldehyde, melamineformaldehyde, urethane, or epoxy resin.
 13. The method of claim 1,wherein the selectively configured porous particulate material is aporous ceramic penetrated with nylon, polyethylene or polystyrene or acombination thereof.
 14. The method of claim 1, wherein the penetratingmaterial and/or coating of the selectively configured porous particulatematerial is capable of trapping or encapsulating a gas having anapparent specific gravity less than the apparent specific gravity of thematrix of the porous particulate material.
 15. The method of claim 1,wherein the porous particulate material is a ceramic and further whereinthe selectively configured porous particulate material is treated with aliquid coating layer or penetrating material which has an ASG less thanthe ASG of the matrix of the porous ceramic.
 16. The method of claim 1,wherein the selectively configured porous particulate material comprisesa multitude of coated porous particulates bonded together and coated orpenetrated with a curable resin.
 17. The method of claim 1, wherein theselectively configured porous particulate material has an apparentdensity from about 1.1 g/cm³ to about 2.6 g/cm³ and a bulk apparentdensity from about 1.03 g/cm³ to about 1.4 g/cm³.
 18. The method ofclaim 1, wherein the size of the selectively configured porousparticulate material is between from about 200 mesh to about 8 mesh. 19.The method of claim 1, wherein the selectively configured porousparticulate material has a coating layer of thickness between from about1 to about 5 microns.
 20. The method of claim 6, wherein the carrierfluid is a completion or workover brine.
 21. The method of claim 6,wherein the carrier fluid is salt water, fresh water, a liquidhydrocarbon, or a gas or a mixture thereof or wherein the selectivelyconfigured porous particulate material is introduced into the well witha liquefied gas or foamed gas carrier fluid or a mixture thereof. 22.The method of claim 21, wherein the gas is nitrogen or carbon dioxide ora mixture thereof or where the liquefied gas or foamed gas carrier fluidis a liquid carbon dioxide based system or nitrogen or a mixture thereofor a foam of nitrogen in liquid carbon dioxide.
 23. The method of claim1, wherein the permeability of the selectively configured porousparticulate material is less than the permeability of the porousparticulate material.
 24. The method of claim 1, wherein the selectivelyconfigured porous particulate material is introduced into the well at aconcentration sufficient to achieve a partial monolayer.
 25. The methodof claim 1, wherein the selectively configured porous particulatematerial is a suspension of the porous particulate material and a porousmatrix, and further wherein the suspension, when introduced into thewell, forms a fluid-permeable gravel pack in an annular area definedbetween the exterior of a screen assembly and the interior of thewellbore.
 26. The method of claim 1, wherein the selectively configuredporous particulate material is a porous particulate material having aglazed surface.
 27. The method of claim 26, wherein the glazed surfaceof the porous particulate material enhances the ease of eithermulti-phase fluid flow or high rate turbulent gas flow through aparticulate pack.
 28. The method of claim 1, wherein the ASG of theporous particulate material is less than or equal to 2.4.
 29. The methodof claim 28, wherein the ASG of the porous particulate material is lessthan or equal to 1.75.
 30. The method of claim 29, wherein the ASG ofthe porous particulate material is less than or equal to 1.25.
 31. Themethod of claim 1, wherein at least a portion of the selectivelyconfigured porous particulate material is placed adjacent thesubterranean formation to form a fluid-permeable pack capable ofreducing or substantially preventing the passage of formation particlesfrom the subterranean formation into the well while allowing passage offormation fluids from the subterranean formation into the well.
 32. Amethod of treating a well penetrating a subterranean formationcomprising introducing into the well a composite of a porous organicpolymeric material treated with a penetrating, coating and/or glazingmaterial wherein air or a fluid is encapsulated by or trapped within theporosity of the porous organic polymeric material.
 33. The method ofclaim 32, wherein the composite is introduced into the well at aconcentration sufficient to achieve a partial monolayer.
 34. The methodof claim 32, wherein the strength of the composite is greater than thestrength of the porous organic polymeric material.
 35. The method ofclaim 32, wherein the selectively configured porous particulate materialis introduced into the well in a slickwater fracturing fluid.
 36. Amethod for treating a well penetrating a subterranean formation,comprising introducing into the well a porous particulate havinginherent or induced permeability, wherein the porous particulate isselected from the group consisting of natural or inorganic ceramicmaterials and synthetic porous particulate materials.
 37. The method ofclaim 36, wherein the porous particulate is a synthetic porousparticulate material selected from the group consisting of polyolefins,styrene-divinylbenzene copolymers and polyalkylacrylate esters.
 38. Themethod of claim 36, wherein the porous particulate is selected from thegroup consisting of natural ceramic materials, styrene-divinylbenzenecopolymers and polyalkylacrylate esters.
 39. The method of claim 36,wherein the porous particulate is a selectively configured porousparticulate material.
 40. The method of claim 39, wherein the apparentspecific gravity of the selectively configured porous particulatematerial is less than the apparent specific gravity of the porousparticulate material.
 41. The method of claim 36, wherein the porosityand permeability of the porous particulate is such that a fluid may bedrawn at least partially into the porous matrix by capillary action. 42.The method of claim 39, wherein the selectively configured porousparticulate material exhibits crush resistance under conditions from2,500 psi to 10,000 psi closure stress.
 43. The method of claim 39,wherein the selectively configured porous particulate material is aporous particulate coated or penetrated with a liquid resin, plastic,cement, sealant, or binder.
 44. The method of claim 43, wherein theselectively configured porous particulate material is a natural ceramic.45. The method of claim 44, wherein the natural ceramic is a lightweightvolcanic rock.
 46. The method of claim 45, wherein the lightweightvolcanic rock is selected from the group consisting of pumice, perlite,Hawaiian basalt, Virginia diabase and Utah rhyolite.
 47. The method ofclaim 36, wherein the porous particulate is introduced into the well ata concentration sufficient to achieve a partial monolayer.
 48. Themethod of claim 36, wherein the porous particulate is introduced intothe well as a slickwater fracturing fluid.
 49. The method of claim 36,wherein the ASG of the porous particulate material is less than or equalto 2.4.
 50. The method of claim 49, wherein the ASG of the porousparticulate material is less than or equal to 2.0.
 51. The method ofclaim 50, wherein the ASG of the porous particulate material is lessthan or equal to 1.75.
 52. The method of claim 51, wherein the ASG ofthe porous particulate material is less than or equal to 1.25.
 53. Themethod of claim 36, wherein the selectively configured porousparticulate material is introduced into the well at a pressuresufficient to cause the formation or enlargement of fractures in thesubterranean formation.
 54. The method of claim 36, wherein at least aportion of the selectively configured porous particulate material isplaced adjacent the subterranean formation to form a fluid-permeablepack capable of reducing or substantially preventing the passage offormation particles from the subterranean formation into the well whileallowing passage of formation fluids from the subterranean formationinto the well.
 55. A method of fracturing a hydrocarbon-bearingformation which comprises introducing to the formation a proppantcomprising a selectively configured porous particulate material, theselectively configured porous particulate comprising a composite of aporous organic polymeric material treated with a penetrating layer orglazing material, wherein the selectively configured porous particulatematerial is introduced into the well at a concentration sufficient toachieve a partial monolayer.
 56. A method of fracturing ahydrocarbon-bearing formation comprising introducing into the formationa selectively configured porous particulate material in a transportfluid, wherein the selectively configured porous particulate materialcomprises a composite of a porous organic polymeric material treatedwith a penetrating and/or coating material and further wherein thepenetrating and/or coating material penetrates the organic polymericmaterial, without invading the porosity of the organic polymericmaterial, to effectively encapsulate air within the porosity of theorganic polymeric material.
 57. The method of claim 56, wherein theorganic polymeric material is an ultra-lightweight organic polymericmaterial
 58. The method of claim 56, wherein the selectively configuredporous particulate is introduced into the well at a concentrationsufficient to achieve a partial monolayer.
 59. The method of claim 56,wherein the selectively configured porous particulate material isintroduced into the well in a slickwater fracturing fluid.